Fortnightly - depreciationhttp://www.fortnightly.com/tags/depreciation
enWind Power Subsidieshttp://www.fortnightly.com/fortnightly/2014/07/wind-power-subsidies
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Today, tomorrow, forever?</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Jonathan A. Lesser</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><strong>Jonathan Lesser</strong> is President, Continental Economics, Inc. Contact him at <a href="mailto:jlesser@continentalecon.com">jlesser@continentalecon.com</a>.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - July 2014</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/1407-OP-ED-fig1.jpg" width="1370" height="911" alt="Figure 1 - Wind Energy Manufacturing Capacity" title="Figure 1 - Wind Energy Manufacturing Capacity" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/1407-OPED.jpg" width="1125" height="894" alt="&quot;Tax credits and renewable mandates are inflicting collateral damage on electric markets and reliability.&quot; - Jonathan Lesser" title="&quot;Tax credits and renewable mandates are inflicting collateral damage on electric markets and reliability.&quot; - Jonathan Lesser" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>In April 2014, the National Renewable Energy Laboratory (NREL) issued a report evaluating the impacts of extending the federal wind production tax credit (PTC), which expired at the end of 2013.<b><sup><a href="http://www.fortnightly.com/fortnightly/2014/07/wind-power-subsidies?page=0%2C3#1" title="1. E. Lantz, et al., 'Implications of a PTC Extension of U.S. Wind Deployment,' Technical Report NREL/TP-6A20-61663, April 2014 (NREL Report).">1</a></sup></b> The NREL Report wrongly concludes that extending the PTC indefinitely is the preferred policy, stating that doing so could "provide the best opportunity to sustain the existing wind installation and manufacturing base at its current level."<b><sup><a href="http://www.fortnightly.com/fortnightly/2014/07/wind-power-subsidies?page=0%2C3#2" title="2. Id. (emphasis in original).">2</a></sup></b> Thus, despite decades of subsidies, NREL concedes that wind generation is <i>still</i> not competitive and recommends continued subsidies to sustain wind energy's manufacturing base and associated jobs.</p>
<p>The NREL Report's recommendation promotes a fundamental "free-lunch" economic fallacy: that artificial production subsidies somehow increase overall economic growth and employment. While basing an entire industry on government subsidies works wonders for the politically-connected beneficiaries of government largesse, the costs that must be borne by everyone else are always - <i>always</i> - far greater.<b><sup><a href="http://www.fortnightly.com/fortnightly/2014/07/wind-power-subsidies?page=0%2C3#3" title="3. For an extended discussion, see Jonathan Lesser, 'Gresham's Law of Green Energy,' Regulation, Winter 2010-2011, pp. 12-18.">3</a></sup></b></p>
<h4><b>The PTC - A History</b></h4>
<p>The PTC began in 1992 as an effort to subsidize wind generation development and jump-start the wind industry, offering a subsidy for each kilowatt-hour (kWh) of electricity produced for a plant's first 10 years of operation. Prior to the PTC, wind generation was subsidized under the auspices of the Public Utility Regulatory Policies Act of 1978. Thus, wind generation has been subsidized continually in one form or another for the last 36 years.</p>
<p>Starting at 1.5 cents/kWh ($15/MWh), the PTC increased each year with the inflation rate. Before its expiration at the end of 2013, the PTC stood at 2.4 cents/kWh ($24/MWh). On a pre-tax basis, that is equivalent to a subsidy of $35/MWh, greater than the average price of electricity in many wholesale markets in 2013.</p>
<p>Although the PTC was never intended to be permanent, it was repeatedly extended by Congress. Only in 2013 was the PTC finally allowed to expire, although wind generating facilities that had simply began construction by the end of 2013 will still be eligible. Moreover, the PTC is not the only subsidy wind generation receives. In addition, wind developers can take advantage of other federal tax incentives, such as accelerated depreciation. And, 30 states, plus the District of Columbia, have renewable portfolio standards (RPS) that force local electric utilities and other retail generation suppliers to purchase increasing percentages of total electricity supplies from wind power.</p>
<p>Whereas the PTC expired at the end of 2013, Congress provided a subsidized lifeline for the wind industry, allowing facilities that were under construction prior to expiration to qualify for the PTC. Moreover, <i>under</i> <i>construction</i> was interpreted quite broadly: facilities that placed orders for wind turbines before the end of the year, for example, would be deemed "under construction." And so, while only about 1,000 MW of new wind generation went on-line in 2013, another 13,000 MW was under construction at the end of that year.<b><sup><a href="http://www.fortnightly.com/fortnightly/2014/07/wind-power-subsidies?page=0%2C3#4" title="4. Todd Woody, 'The Crazy Economics of the Wind Industry in Two Charts,' The Atlantic, May 5, 2014. http://www.theatlantic.com/technology/archive/2014/05/the-crazy-economics-of-the-wind-industry-in-two-charts/361672/">4</a></sup></b> Thus, the extension amounts to a multi-year phase out of the PTC, which the Congressional Budget Office estimated would cost taxpayers an additional $12 billion.</p>
<h4><b>Is Wind Generation Competitive?</b></h4>
<p>Yet, despite the PTC, accelerated depreciation, and RPS mandates, the NREL report concludes that new wind generation development will be relatively low "unless additional incentives are provided that result in wind being cost competitive with <i>existing</i> gas-fired generation"<b><sup><a href="http://www.fortnightly.com/fortnightly/2014/07/wind-power-subsidies?page=0%2C3#5" title="5. NREL Report, p. vi.">5</a></sup></b> and that "without policy support to enhance the cost position of wind power, purely economic development will also likely be modest."<b><sup><a href="http://www.fortnightly.com/fortnightly/2014/07/wind-power-subsidies?page=0%2C3#6" title="6. Id., p. 4.">6</a></sup></b> The NREL report considers "modest growth" to be between 3,000 and 5,000 additional MW of new capacity each year, or between 5% and 8% based on the 60,000 MW of installed wind generation today. Given that U.S. electricity demand growth is projected to be less than one percent annually between 2012 and 2040,<b><sup><a href="http://www.fortnightly.com/fortnightly/2014/07/wind-power-subsidies?page=0%2C3#7" title="7. US Energy Information Administration, 'Implications of Low Electricity Demand Growth,' 2014 Annual Energy Outlook, April 30, 2014. Available at: http://www.eia.gov/forecasts/aeo/section_issues.cfm#elec_demand">7</a></sup></b> a 5-8% annual growth in wind capacity in the absence of subsidies is hardly evidence that subsidies must be continued.</p>
<p>The NREL report directly contradicts assertions made by the American Wind Energy Association (AWEA) that wind is cheaper than other generating resources. For example, AWEA cites to a US Department of Energy study to assert that "the cost of wind energy has declined by 43% over the last four years," and that "wind energy is one of the most affordable options for new electricity generation."<b><sup><a href="http://www.fortnightly.com/fortnightly/2014/07/wind-power-subsidies?page=0%2C3#8" title="8. AWEA, 'Wind Power's Consumer Benefits,' February 2014. Available at: http://awea.files.cms-plus.com/AWEA%20White%20Paper-Consumer%20Benefits.pdf">8</a></sup></b> Then again, no less an investor than Warren Buffett, CEO of Berkshire Hathaway, stated that the only reason his company builds wind turbines is to obtain the accompanying tax credits. "That the only reason to build them. They don't make sense without the tax credit."<b><sup><a href="http://www.fortnightly.com/fortnightly/2014/07/wind-power-subsidies?page=0%2C3#9" title="9. Stephen Gandel, 'Warren Buffett: We took a stand on Coke's pay package,' Fortune, April 28, 2014. http://finance.fortune.cnn.com/2014/04/28/warren-buffett-coke-interview/.">9</a></sup></b></p>
<h4><b>The Jobs Fallacy</b></h4>
<p>One of most common justifications for continuing wind generation subsidies, including the PTC, is based on supporting a US manufacturing base and creating jobs. The argument is straightforward: without the PTC, industries that support wind turbine manufacturing are not sustainable and the result will be lost jobs. As the NREL report states, "Given the limited export market, a reduction in domestic wind power deployment is likely to have a direct and negative effect on U.S.-based wind turbine manufacturing production and employment."<b><sup><a href="http://www.fortnightly.com/fortnightly/2014/07/wind-power-subsidies?page=0%2C3#10" title="10. NREL Report, p. 14.">10</a></sup></b> In other words, the US wind-turbine manufacturing industry <i>requires</i> subsidized wind energy to survive.</p>
<p>However, a report published in 2012 by the nonpartisan US Congressional Research Service<b><sup><a href="http://www.fortnightly.com/fortnightly/2014/07/wind-power-subsidies?page=0%2C3#11" title="11. Philip Brown, 'U.S. Renewable Electricity: How Does the Production Tax Credit (PTC) Impact Wind Markets?' US Congressional Research Service, June 20, 2012 (Brown 2012). Available at: www.crs.gov.">11</a></sup></b> shows that there will be excess wind industry manufacturing capacity - estimated to be about 14,000 MW per year - even if the PTC is extended permanently (see Figure 1).</p>
<p>That amount of manufacturing capacity cannot be sustained because it's simply not possible to add 14,000 MW of new wind capacity each year onto the US electrical grid, given the projected low growth in overall US electricity demand and the adverse impacts of subsidized wind generation on wholesale power markets, including premature retirement of baseload nuclear plants, which would increase electric prices and lead to higher carbon emissions.<b><sup><a href="http://www.fortnightly.com/fortnightly/2014/07/wind-power-subsidies?page=0%2C3#12" title="12. See, e.g., Hannah Northey, 'Spate of reactor closures threatens U.S. climate goals - DOE,' Energy and Environment News, Subscription, February 5, 2014. Available at: http://www.eenews.net/greenwire/stories/1059994082.">12</a></sup></b></p>
<p>As for why there is a limited export market for US manufactured wind turbine components, the NREL Report states that the causes are relatively high shipping costs for turbine components and high U.S. labor costs: "In the United States, the factory gate prices for components like blades, which are labor-intensive to produce, also tend to be higher than the prices of the same goods manufactured in many other regions, further limiting export opportunities from U.S.-based facilities."<b><sup><a href="http://www.fortnightly.com/fortnightly/2014/07/wind-power-subsidies?page=0%2C3#13" title="13. Id.">13</a></sup></b> In other words, US manufactured wind turbine components cost too much to compete in the world market.</p>
<p>Thus, according to NREL, if the US wishes to maintain an already subsidy-larded domestic wind manufacturing industry at its current capacity, we must increase the demand for wind turbines artificially with perpetual subsidies. But even then, the US electric market cannot absorb all of that generating capacity.</p>
<p>From a macroeconomic standpoint, policies that subsidized manufacturing end up <i>reducing</i> economic growth. Moreover, if one accepts the implicit reasoning of the PTC - that U.S. manufacturing industries should be subsidized through artificially induced demand to boost economic growth and employment - then why just the wind industry? Why not other industries - automobiles, steel, apparel? For example, to increase the demand for domestically manufactured automobiles, Congress could require consumers to purchase a new car every five years and bar any cars older than five years from the public highways. Such mandates could be combined with tax credits for purchases made from domestic manufacturers.</p>
<p>No doubt, such an example will strike most readers as absurd. The fact that we do not subsidize every industry by creating artificial demand, or provide tax credits for every U.S. product purchased, stems from a basic economic truth: artificial subsidies cannot produce long-term economic growth. To believe otherwise is to believe in the proverbial economic "free lunch," by which something can be had for nothing.</p>
<p>In reality, wind energy subsidies such as the PTC and RPS mandate are paid for by everyone else. <i>Every</i> consumer and <i>every</i> business owner pays for these subsidies, just as they pay for all other subsidies, whether mandates for corn-based ethanol, which drive up food prices and increase pollution, or mandates that oil refineries use minimum quantities of cellulosic ethanol that do not physically exist.</p>
<p>Moreover, with wind energy, the subsidies do not end with the PTC and RPS mandates. Consumers and businesses must also pay for the additional high-voltage transmission lines to interconnect wind generation, which is generally located far from population centers, to the electric grid. For example, whereas the NREL Report cites Texas as an example of where wind generation can compete successfully,<b><sup><a href="http://www.fortnightly.com/fortnightly/2014/07/wind-power-subsidies?page=0%2C3#14" title="14. Id., p. 4. 'To date, the PTC and other federal tax incentives (e.g., accelerated depreciation) have boosted wind power's economic position relative to alternative generation sources, enabling wind to be lower cost than other generation technologies in some regions (e.g., Texas).' (footnote omitted).">14</a></sup></b> that state has spent over $7 billion to deliver wind energy from the rural western part of the state to the population centers in the southeast. And, because wind generation is intermittent - producing power only when the wind blows - additional monies must be spent on backing up that capacity with fossil-fuel generation to ensure the electric grid can operate safely and reliably. Again, those costs are borne by consumers and businesses, not wind generation owners.</p>
<h4><b>Time for a Sensible Policy</b></h4>
<p>The PTC and RPS mandates are inflicting collateral damage on wholesale electric markets and electric system reliability. Although AWEA touts wind energy's ability to "suppress" wholesale market prices and thereby benefit consumers, in fact such price suppression is one more manifestation of the <i>adverse</i> impacts of subsidies. Distorting competitive markets hurts consumers and producers who lack sufficient political clout to receive such subsidized largesse.</p>
<p>Let's consider a better approach: allow competitive markets to work as they are intended. The NREL report itself estimates that wind generation development will continue even in the absence of the PTC. AWEA insists that wind energy is competitive, if not cheaper, than conventional generating resources. If so, then there is no basis for continued subsidies. And if not, then are 36 years of wind power subsidies not sufficient? How many more years must wind generation be subsidized for it to become competitive?</p>
<p>Many European countries have discovered just how expensive subsidized renewable energy can be, as electric prices have skyrocketed and businesses have discovered they cannot compete in global markets because of their high energy costs. Must the US fall over the same cliff to realize that wind subsidies impose a huge economic cost?</p>
<p>Wind energy, along with all other types of generation, should demonstrate it can compete on its own merits. If wind energy truly costs less than other resources, it has no need for additional subsidies. But if wind still cannot compete, despite 36 years of subsidies and mandates, it is time to say "enough." The US electric industry, and the entire US economy, today faces enough challenges without the added burden of endless subsidies for the wind industry.</p>
<h4>Endnotes:</h4>
<p><a name="1" id="1"></a>1. E. Lantz, <i>et al.</i>, "Implications of a PTC Extension of U.S. Wind Deployment," Technical Report NREL/TP-6A20-61663, April 2014 (NREL Report).</p>
<p><a name="2" id="2"></a>2. <i>Id</i>. (emphasis in original).</p>
<p><a name="3" id="3"></a>3. For an extended discussion, <i>see</i> Jonathan Lesser, "Gresham's Law of Green Energy," <i>Regulation</i>, Winter 2010-2011, pp. 12-18.</p>
<p><a name="4" id="4"></a>4. Todd Woody, "The Crazy Economics of the Wind Industry in Two Charts," <i>The Atlantic</i>, May 5, 2014. <a href="http://www.theatlantic.com/technology/archive/2014/05/the-crazy-economics-of-the-wind-industry-in-two-charts/361672/">http://www.theatlantic.com/technology/archive/2014/05/the-crazy-economic...</a></p>
<p><a name="5" id="5"></a>5. NREL Report, p. vi.</p>
<p><a name="6" id="6"></a>6. <i>Id</i>., p. 4.</p>
<p><a name="7" id="7"></a>7. US Energy Information Administration, "Implications of Low Electricity Demand Growth," 2014 Annual Energy Outlook, April 30, 2014. Available at: <a href="http://www.eia.gov/forecasts/aeo/section_issues.cfm#elec_demand">http://www.eia.gov/forecasts/aeo/section_issues.cfm#elec_demand</a></p>
<p><a name="8" id="8"></a>8. AWEA, "Wind Power's Consumer Benefits," February 2014. Available at: <a href="http://awea.files.cms-plus.com/AWEA%20White%20Paper-Consumer%20Benefits.pdf">http://awea.files.cms-plus.com/AWEA%20White%20Paper-Consumer%20Benefits.pdf</a></p>
<p><a name="9" id="9"></a>9. Stephen Gandel, "Warren Buffett: We took a stand on Coke's pay package," <i>Fortune</i>, April 28, 2014. <a href="http://finance.fortune.cnn.com/2014/04/28/warren-buffett-coke-interview/">http://finance.fortune.cnn.com/2014/04/28/warren-buffett-coke-interview/</a>.</p>
<p><a name="10" id="10"></a>10. NREL Report, p. 14.</p>
<p><a name="11" id="11"></a>11. Philip Brown, "U.S. Renewable Electricity: How Does the Production Tax Credit (PTC) Impact Wind Markets?" US Congressional Research Service, June 20, 2012 (Brown 2012). Available at: <a href="http://www.crs.gov">www.crs.gov</a>.</p>
<p><a name="12" id="12"></a>12. <i>See, e.g</i>., Hannah Northey, "Spate of reactor closures threatens U.S. climate goals - DOE," Energy and Environment News, Subscription, February 5, 2014. Available at: <a href="http://www.eenews.net/greenwire/stories/1059994082">http://www.eenews.net/greenwire/stories/1059994082</a>.</p>
<p><a name="13" id="13"></a>13. <i>Id</i>.</p>
<p><a name="14" id="14"></a>14. <i>Id</i>., p. 4. "To date, the PTC and other federal tax incentives (<i>e.g.</i>, accelerated depreciation) have boosted wind power's economic position relative to alternative generation sources, enabling wind to be lower cost than other generation technologies in some regions (<i>e.g.</i>, Texas)." (footnote omitted).</p>
</div></div></div><div class="field field-name-field-article-category field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Category (Actual): </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/article-categories/wind">Wind</a></li><li class="taxonomy-term-reference-1"><a href="/article-categories/accounting-depreciation">Accounting &amp; Depreciation</a></li></ul></div><div class="field field-name-field-members-only field-type-list-boolean field-label-above"><div class="field-label">Viewable to All?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-article-featured field-type-list-boolean field-label-above"><div class="field-label">Is Featured?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-department field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Department: </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/department/op-ed">Op-Ed</a></li></ul></div><div class="field field-name-field-image-picture field-type-image field-label-above"><div class="field-label">Image Picture:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/1407-Op-ed2.jpg" width="1035" height="675" alt="" /></div></div></div><div class="field field-name-field-fortnightly-40 field-type-list-boolean field-label-above"><div class="field-label">Is Fortnightly 40?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-law-lawyers field-type-list-boolean field-label-above"><div class="field-label">Is Law &amp; Lawyers:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-tags field-type-taxonomy-term-reference field-label-above clearfix">
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<a href="/tags/wind">Wind</a><span class="pur_comma">, </span><a href="/tags/subsidies">Subsidies</a><span class="pur_comma">, </span><a href="/tags/national-renewable-energy-laboratory-0">National Renewable Energy Laboratory</a><span class="pur_comma">, </span><a href="/tags/nrel-0">NREL</a><span class="pur_comma">, </span><a href="/tags/federal">federal</a><span class="pur_comma">, </span><a href="/tags/tax">tax</a><span class="pur_comma">, </span><a href="/tags/ptc">PTC</a><span class="pur_comma">, </span><a href="/tags/competitive">competitive</a><span class="pur_comma">, </span><a href="/tags/manufacturing">manufacturing</a><span class="pur_comma">, </span><a href="/tags/economic">economic</a><span class="pur_comma">, </span><a href="/tags/government">government</a><span class="pur_comma">, </span><a href="/tags/generation">generation</a><span class="pur_comma">, </span><a href="/tags/public-utility-regulatory-policies-act">Public Utility Regulatory Policies Act</a><span class="pur_comma">, </span><a href="/tags/accelerated">accelerated</a><span class="pur_comma">, </span><a href="/tags/depreciation">depreciation</a><span class="pur_comma">, </span><a href="/tags/renewable">Renewable</a><span class="pur_comma">, </span><a href="/tags/rps">RPS</a><span class="pur_comma">, </span><a href="/tags/construction">construction</a><span class="pur_comma">, </span><a href="/tags/congressional">Congressional</a><span class="pur_comma">, </span><a href="/tags/american-wind-energy-association">American Wind Energy Association</a><span class="pur_comma">, </span><a href="/tags/awea">AWEA</a><span class="pur_comma">, </span><a href="/tags/affordable">affordable</a><span class="pur_comma">, </span><a href="/tags/warren-buffett">Warren Buffett</a><span class="pur_comma">, </span><a href="/tags/berkshire-hathaway">Berkshire Hathaway</a><span class="pur_comma">, </span><a href="/tags/sustainable">sustainable</a><span class="pur_comma">, </span><a href="/tags/jobs">jobs</a><span class="pur_comma">, </span><a href="/tags/export">export</a><span class="pur_comma">, </span><a href="/tags/nuclear">Nuclear</a><span class="pur_comma">, </span><a href="/tags/factory">factory</a><span class="pur_comma">, </span><a href="/tags/labor">labor</a><span class="pur_comma">, </span><a href="/tags/market">market</a><span class="pur_comma">, </span><a href="/tags/long-term">long-term</a><span class="pur_comma">, </span><a href="/tags/corn">corn</a><span class="pur_comma">, </span><a href="/tags/pollution">Pollution</a><span class="pur_comma">, </span><a href="/tags/high-voltage">high-voltage</a><span class="pur_comma">, </span><a href="/tags/grid-0">grid</a><span class="pur_comma">, </span><a href="/tags/consumers">consumers</a><span class="pur_comma">, </span><a href="/tags/business">business</a><span class="pur_comma">, </span><a href="/tags/mandates">Mandates</a><span class="pur_comma">, </span><a href="/tags/collateral">collateral</a> </div>
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Sun, 29 Jun 2014 15:07:18 +0000meacott17371 at http://www.fortnightly.comFive Years Laterhttp://www.fortnightly.com/fortnightly/2013/10/five-years-later
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Wall Street is back in business. What’s next for utility finance?</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p class="p1">Michael T. Burr</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p class="p1"><b>Michael T. Burr</b> is <span class="s1"><i>Fortnightly’s</i></span> editor-in-chief. Email him at <a href="mailto:burr@pur.com">burr@pur.com</a></p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - October 2013</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/1310-FEA1-fig1.jpg" width="1022" height="1025" alt="Figure 1 - Big Build and the Great Recession" title="Figure 1 - Big Build and the Great Recession" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/1310-FEA1-Napolitano.jpg" width="1002" height="849" alt="&quot;Capital markets are vibrant and healthy. It feels like the end of a five-year cycle of fear and distress.&quot; - Frank Napolitano, RBC Capital Markets" title="&quot;Capital markets are vibrant and healthy. It feels like the end of a five-year cycle of fear and distress.&quot; - Frank Napolitano, RBC Capital Markets" /></div><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/1310-FEA1-fig2.jpg" width="1026" height="907" alt="Figure 2 - Power &amp; Gas Debt Issues" title="Figure 2 - Power &amp; Gas Debt Issues" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/1310-FEA1-Bilicic.jpg" width="1002" height="841" alt="&quot;There’s a sense that regulators are suffering from rate-filing fatigue, and rate proceedings will become more difficult.&quot; - George Billicic, Lazard" title="&quot;There’s a sense that regulators are suffering from rate-filing fatigue, and rate proceedings will become more difficult.&quot; - George Billicic, Lazard" /></div><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/1310-FEA1-fig3.jpg" width="2056" height="783" alt="Figure 3 - Major Power Asset Acquisitions" title="Figure 3 - Major Power Asset Acquisitions" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/1310-FEA1-Kind.jpg" width="1002" height="841" alt="&quot;If a company will sell assets in this market, it’s not because they think they’ll get good proceeds.&quot; - Peter Kind, Energy Infrastructure Advocates" title="&quot;If a company will sell assets in this market, it’s not because they think they’ll get good proceeds.&quot; - Peter Kind, Energy Infrastructure Advocates" /></div><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/1310-FEA1-Nastro.jpg" width="1006" height="851" alt="&quot;Investors will start differentiating utilities by regulatory compact.&quot; - David Nastro, Morgan Stanley" title="&quot;Investors will start differentiating utilities by regulatory compact.&quot; - David Nastro, Morgan Stanley" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>When the storied investment bank Lehman Brothers declared bankruptcy on Sept. 15, 2008, it marked the official beginning of the worst financial crisis in recent history.</p>
<p>The fact is, however, that by the time Lehman went bankrupt, a crisis already had been brewing for at least 18 months. The subprime lending meltdown began in early 2007, when median home sales prices in the United States began sharply declining from their January peak. By the end of 2007, the subprime mortgage crisis was looking like a debt crisis generally, and we were already talking about a recession and its possible effect on utilities. </p>
<p>Specifically, in our October 2007 financial report, we wrote: “the industry’s financial health arguably has nowhere to go but downward in the months and years to come. </p>
<p>“Utility companies are bringing monumental capital expenditure plans before rate regulators just as they’re dealing with a barrage of rising costs – for fuel and other commodities, as well as labor, pension-fund obligations, and interest payments. Additionally, with the threat of greenhouse-gas (GHG) regulation looming in the 2009 to 2013 time frame, utilities face unpredictable environmental-compliance costs. </p>
<p>“Many utility companies and their investors expect regulators will support utilities’ capital requirements with progressive rate structures, including accelerated rate-recovery for cap-ex spending. But as costs escalate, utilities’ rate demands seem certain to test the limits of regulators’ support.” (<i>See “</i><a href="http://www.fortnightly.com/fortnightly/2007/10/2007-finance-roundtable-pricing-regulatory-risk" target="_blank"><i>2007 Finance Roundtable: Pricing Regulatory Risk</i></a><i><a href="http://www.fortnightly.com/fortnightly/2007/10/2007-finance-roundtable-pricing-regulatory-risk" target="_blank">,</a>”</i> <i>October 2007.</i>) </p>
<p>Those predictions – a full year before the official start of the financial crisis – were mostly accurate. But as it turns out, we missed some things. For one thing, we didn’t predict that the debt markets would actually freeze up in the depths of the crisis. We didn’t imagine the financial meltdown would pull down Lehman Brothers, and drag some other banks so close to the brink that Congress would step in with the $700 billion Wall Street bailout. And we didn’t know that the ensuing economic decline would get its very own proper noun: the Great Recession.</p>
<p>Moreover, we didn’t know that natural gas prices would plunge and stay down in the low single digits per million Btu, driven by a slow economy and a boom in shale development. We did guess that interest rates would decline, but we didn’t understand just how far the Federal Reserve would go to pump money into the economy. As Treasury rates flirted with the number zero, utilities began refinancing their bonds to free up cash flow. Then, Congress passed an economic stimulus bill that provided bonus depreciation for capital investments, which in many cases allowed utilities to invest without raising much debt or equity capital. </p>
<p>These factors brought remarkable results in the electric and gas industry. Utilities plowed money into infrastructure all through the Great Recession (<i>see Figure 1</i>) – a trend that we actually did predict in October 2008, as we saw investment costs declining and policy changes on the way. “[S]ome companies might accelerate their investments, taking advantage of falling prices for building materials and labor, and an increase of available contractors in a slowing industrial market. Plus, if political winds continue blowing in their current direction, the industry might benefit from a wave of financial incentives for capital investments and energy technology development and demonstration.” (<i>See “</i><a href="http://www.fortnightly.com/fortnightly/2008/10/path-forward"><i>The Path Forward</i></a><i>,”</i> <i>October 2008.</i>) </p>
<h4><b>Harnessing Headwinds</b></h4>
<p>The path the industry has taken since 2008 has been influenced substantially by government policy changes and incentives. Most notably, the American Recovery and Reinvestment Act of 2009 (ARRA) provided extra impetus for smart metering and other distribution technology investments that companies otherwise might’ve put on the back burner. In addition, FERC incentive rates and remotely sited renewable energy development drove transmission investments. Renewed and enhanced federal tax credits spurred major investments in utility-scale wind and solar farms. New EPA regulations prompted major environmental upgrades and retrofits. And gas safety standards – prompted by tragic disasters at aging pipelines – sparked gas distribution investments. </p>
<p>As a consequence, investor-owned power and gas companies spent $400 billion on U.S. capital projects between 2008 and the end of 2012. Even more remarkably, throughout this period of heavy investment, despite the suffering economy and anemic energy markets, investor-owned utilities generally maintained positive cash flow, strong dividends, excellent credit metrics, and easy access to capital markets.</p>
<p>“The regulated utilities sector has actually done a little better than we’d originally projected in our financial models,” says James Hempstead, a senior vice president with Moody’s Investors Service. He cites tax benefits like bonus depreciation, as well as a stable regulatory environment. “Across the country, regulatory agencies have been very supportive for utility cost recovery, providing decisions on a timely basis and approving a series of trackers and rate riders for single-issue recovery mechanisms. We think that’s a good thing, because it provides a degree of transparency and timeliness to cost recovery.”</p>
<p>The same observations can’t, however, be applied to unregulated power companies, for whom low commodity prices and a flight to quality on Wall Street have resulted in a starvation diet. “Companies are hunkering down to protect liquidity,” Hempstead says. “They’re harvesting assets and squeaking out efficiencies to improve cash flows. It’s been a difficult market for the unregulated power sector.”</p>
<p>Indeed, several major independent power companies have gone through major financial distress in the past five years:</p>
<p>• AES Eastern Energy filed bankruptcy at the end of 2011. </p>
<p>• Bicent Holdings and 12 of its affiliates sought bankruptcy protection in April 2012. </p>
<p>• GenOn saw its share prices plunge from more than $25 in 2007 to less than $2 when NRG Energy agreed to acquire the company in July 2012. </p>
<p>• Dynegy filed Chapter 11 in July 2012. </p>
<p>• Edison Mission Energy filed bankruptcy in December 2012. </p>
<p>Today, with power prices remaining persistently low, the difficulty isn’t over for unregulated power companies. At this writing, analysts were predicting a November 1 bankruptcy filing for Energy Future Holdings subsidiary Texas Competitive Electric Holdings, which includes wholesale generator Luminant and retailer TXU Energy.</p>
<p>Some other unregulated power companies are selling off generating assets – sometimes despite weak market valuations – in an effort to buttress their balance sheets. Secondary market activity also is driven by strategic moves among unregulated generators and utilities, as well as the investment cycles of private equity funds and institutional investors seeking to capture what value they can from mature assets languishing in their portfolios. (<i>See Figure 3.</i>)</p>
<p>Further, some companies are exploring options for capturing higher valuation multiples from portfolios of similar assets – most notably through so-called “yieldco” (yield company) and master limited partnership (MLP) structures. In March, for example, OGE Energy, CenterPoint Energy, and ArcLight Partners agreed to form an MLP that will own OGE and CenterPoint’s interstate pipelines, midstream, and field services businesses, with the intent of raising equity through an initial public offering (IPO). And in July, NRG raised $462 million through the IPO of NRG Yield, an investment vehicle for several generating plants and development projects with long-term power purchase agreements. </p>
<p>To better understand how the industry has weathered the past five years – and how it’s positioned for the years to come – we spoke with several finance executives. </p>
<p>• Peter Kind, Energy Infrastructure Advocates</p>
<p>• Matt LeBlanc, JPMorgan Chase</p>
<p>• George Bilicic, Lazard</p>
<p>• David Nastro, Morgan Stanley</p>
<p>• Frank Napolitano, RBS Capital Markets</p>
<p>• James Hempstead, Ryan Wobbrock, Mike Haggerty, and Jeffrey Cassella, Moody’s</p>
<p>Their perspectives suggest America’s power and gas companies will continue to find a welcome reception on Wall Street – even as they face an increasingly complex future.</p>
<p><b>FORTNIGHTLY</b> It’s been five years since the financial crisis began. How has the power and gas industry weathered the crisis? What’s the general outlook for access to capital today?</p>
<p><b>Napolitano, RBC Capital Markets:</b> Five years after the start of the worst financial crisis in recent history, and the markets are as open as they were before, and even more open in terms of available capital products and investors for those products. </p>
<p>Last year we could’ve said IPOs were possible for contracted renewable companies, subject to market conditions and pricing. Since then we’ve seen successful IPOs of yieldcos. Most recently Pattern Energy announced its IPO. [The company planned to raise $320 million.] MLPs and yieldcos are a hot trend in power and gas financing. </p>
<p>In general capital markets are vibrant and healthy. Costs for issuing securities are better than they’ve been 95 percent of the time. It hasn’t felt this way since 2006, and the fundamentals are rational. It feels like the end of a five-year cycle of fear and distress.</p>
<p><b>Nastro, Morgan Stanley:</b> Year-to-date, we are very close to the 20-year record that was set for corporate debt issuance in 2007. Corporate boards are gaining confidence and are more comfortable borrowing money than they’ve been at any time since the financial crisis. </p>
<p>Historically, lower Treasury yields correlated with higher investment-grade credit spreads. But if you look at 2012 and 2013, markets dislocated from this trend and we’ve seen only a modest widening of spreads. The combination of historically low Treasury yields and relatively tight credit spreads has translated into historically attractive financing costs.</p>
<p>In the leveraged finance market, we’ve seen the technical underpinning improving, with the refinancing wave from 2010 to the present. Near-term maturities have either been refinanced or addressed through amend-and-extend transactions. The leveraged finance market continues to be healthy coming out of the crisis, and we expect to see further issuance with the expansion of European and international markets. </p>
<p>Coming out of the Eurozone banking crisis, the old project finance banking market is significantly weaker than it was. Bank downgrades and Basel III requirements have forced banks to shore up their capital levels. Fewer banks are providing capital and generally are lending only to core relationship clients, with higher fees and pricing. But as traditional project commercial lenders exit that market, the capital markets have been filling the void. Capital market investors have ample capacity and a desire for structured bonds. As investors continue searching for yield in a low interest-rate environment, they’re more interested in structured credits. </p>
<p><b>Bilicic, Lazard</b>: Utilities continue to provide a very attractive risk-adjusted total return proposition to shareholders, because of the dividends they offer and some reasonable growth that goes along with that dividend proposition. This has been particularly important in the volatile equity markets over the past few years, and has allowed utilities to offer a differentiated and useful investment proposition.</p>
<p>Going forward, the industry could start to cycle into a period with modestly increased earnings challenges driven by load-growth issues, rate pressures, and other factors. Some industry participants will be successful in addressing these earnings challenges and some might not. Further, while it is tiresome for industry participants to hear this observation, long-term interest rates eventually will begin rising, placing pressure on valuations and the need to show growth.</p>
<p>These potential negative trends could affect valuation levels, but if one views the historical access to capital for the utility industry and the depths of the relevant capital markets, it’s hard to see how capital markets access – as opposed to valuation levels – will be impaired in any material manner. </p>
<p><b>Haggerty, Moody’s:</b> The industry has been incredibly resilient. We remember the dour mood at the EEI Financial Conference in 2008, but the sector was still accessing the markets because there was a flight to quality.</p>
<p>Low gas prices and low interest rates have been big contributors to the credit quality of the sector. Interest rates might go up, but not quickly or immediately, and companies should be able to adapt. </p>
<p>Bonus depreciation has been helpful, and it’s kept metrics inflated a couple of percentage points higher than they’d normally be. As that comes off, it could put pressure on metrics and challenge companies’ ability to keep up capital spending without going in for a rate case. It’s not a game changer, but something management has to deal with going forward.</p>
<p><b>LeBlanc, JPMorgan Chase:</b> Sophisticated utilities with access to capital markets have turned their debt over to lock in low fixed coupon rates. As issuers, they’re focused on maintaining investment-grade ratings as a core commitment to regulators and customers. </p>
<p>We focus mostly on the project financing and structured financing market. With pressure on European banks and insurers related to regulatory capital adequacy, you have fewer players in that space. Some Canadian, Japanese, and U.S. banks are participating, but with fewer capital providers, you see spreads widenening.</p>
<p>We see a huge opportunity in the U.S. to deploy money in the energy and power value chain, especially midstream and closer to the demand side. We think it’s a $1 trillion investment opportunity over 10 years – and that’s all new money going in, not considering existing assets that might change hands. </p>
<p><b>FORTNIGHTLY</b> Utilities are facing pressure on both allowed returns on equity (ROE) in rate cases, and earned ROEs. How does pressure on ROEs affect utility financing and access to capital?</p>
<p><b>Kind, Energy Infrastructure Advocates:</b> Low interest rates have led to low ROEs, and that creates a competitive dynamic. As other states look to what’s being granted by neighboring states, it focuses attention on keeping rates reasonably low. </p>
<p>Earned ROEs are where the rubber meets the road, and they have lagged allowed ROEs. In a market where load growth is modest – or nil – investors are concerned about a company’s ability to earn its allowed ROE. Coverage ratios go lower, and that affects your credit metrics. It’s a cycle.</p>
<p><b>LeBlanc:</b> Regulators are saying ROEs should come down as financing costs come down. But that makes it difficult in a rising-rate environment, when you’re no longer competitive with other entities that are issuing debt. It will put utilities in a bind, if and when these things play out. </p>
<p><b>Napolitano: </b>Pressure on ROEs is coming in utility rate cases. We’ve seen a variety of regional outcomes. ROEs in the Southeast are generally higher than in other regions. The exercise for utilities now is to get what they need for reliability and green power investments, without accelerating costs onto bill payers. </p>
<p><b>Nastro:</b> We’re concerned that as interest rates start moving up, we might not see a commensurate rise in ROEs on a timely basis. </p>
<p>Because ROEs are facing downward pressure, utilities are reluctant to file general rate cases. They’re asking regulatory commissions to provide forward-looking recovery mechanisms to reduce lag, such as trackers that allow them to stay out of rate cases for longer and a focus on managing non-fuel O&amp;M costs. Investors likely will start differentiating utilities by regulatory compact. They’ll seek shelter in this rate storm with utilities in states like California and Illinois, where the ROE construct has some degree of interest rate protection.</p>
<p><b>FORTNIGHTLY</b> Several large mergers were completed in the last couple of years. Now only one major transaction is pending – MidAmerican Energy’s acquisition of NV Energy. What factors are affecting utilities today as they consider M&amp;A activity?</p>
<p><b>Nastro:</b> Buyers have been aggressive as they try to pry loose non-core regulated assets. For example, Laclede bought Missouri Gas [for $975 million, closing September 1], and TECO Energy is acquiring New Mexico Gas [for $950 million, closing expected in early 2014]. Those sales resulted in robust auctions with strategic and financial buyers lowering their hurdle rates as they actively look for new growth opportunities. Regulated utilities are also looking to take advantage of their strong currency and historically low financing costs to make things happen.</p>
<p>MidAmerican wasn’t alone in looking at the opportunity to acquire NV Energy. Other strategic buyers also looked at that business and were willing to reach geographically for new growth avenues. There are a limited number of contracted and regulated opportunities out there, and we’ve seen aggressive buyers and long lines in recent auction processes.</p>
<p><b>Kind:</b> Each transaction has its own rationale. The themes that have driven deals are management succession issues, the need for synergies to mitigate rate increases, or scale to support raising capital. I suspect that over the next several years, rate-case activity will be fairly active, and that might put a dent in the level of M&amp;A activity. It’s not typically conducive to seek merger approval while you’re processing a rate case. This might be less of a factor for the big companies that are always processing rate cases, but for smaller companies, the single-state utilities, it’s harder to do.</p>
<p>Also it’s fair to say that when deals are announced, the companies that aren’t involved will reassess the landscape. Companies don’t want to be left out if there are potential partners they want to pursue. They start asking questions, and that’s how a wave gets started. </p>
<p>For companies whose valuation is dependent on power prices, their stocks are being challenged, and they don’t have a strong currency right now to consider acquisitions. At some point they might consider strategic acquisitions to create scale. But in general low commodity prices aren’t helpful to the stock prices of merchant players, and they’re holding back, trying to figure out how to stabilize their profitability. </p>
<p><b>Bilicic:</b> M&amp;A activity ebbs and flows, but there is a consistent story across the industry – it’s consolidating slowly and steadily. At the moment there are something like 52 publicly traded electric utilities. Twenty years ago, there were 95 or 96. We expect consolidation to continue, because value can be created through M&amp;A that can materially exceed the stand-alone case. While some will move forward smoothly, others will struggle as a result of regulatory approval issues and questionable industrial logic. </p>
<p><b>LeBlanc:</b> It varies from one jurisdiction to another, but companies tend to view themselves as fully valued in the current stock market. Nobody wants to buy at the top of the market. </p>
<p>I think it will get harder for companies to merge. That creates an opportunity for private capital to come in. It won’t be a panacea but it can provide capital in partnering situations.</p>
<p><b>FORTNIGHTLY</b> We see a strong flow of asset deals lately. What’s driving that activity and how are asset M&amp;A trends and strategies evolving?</p>
<p><b>Kind:</b> To the extent you’re holding a merchant generation asset in a low power-price environment, your profitability has been affected. The asset market is pretty challenged. While power prices remain low, it will continue to be a buyer’s market. If a company will sell assets in this market, it’s not because they think they’ll get good proceeds, but because they need to reduce risk factors. Some distressed companies might need to sell assets to raise cash, or they’ll be taken over in bankruptcy and the new owners will sell those assets.</p>
<p><b>Napolitano:</b> Because the debt markets are wide open and available at all levels of credit quality, buyers can build a capital structure to acquire assets for cash. This is a point of progress. In 2008 there was no M&amp;A because there was no access to capital. In 2010 the market started to come back, and in 2011 and 2012 companies were more and more successful. Now in 2013, the buy side is well capitalized again, and the market is wide open, with buyers and sellers of everything – midstream, coal, gas, renewables, you name it. In my entire career, I’ve never seen more things for sale, of all types, in the U.S. power and utility asset space. </p>
<p>In some cases, the owners are private equity funds and they’ve reached the end of a hold period, and they need to cycle capital. In other cases, strategic investors are simplifying their business models. Ameren is an example; the company’s non-investment grade genco wasn’t creating shareholder value, so Ameren decided to exit the business. Some companies are bolstering a business that they consider to be their core, or entering one that seems to have better growth prospects. </p>
<p>When you have that kind of market, with many different participants, people start to aggregate assets around strategies: bringing a portfolio together and finding buyers; or seeking uplift through a public offering; or just operating the portfolio. There’s a belief in the market that valuations will improve from where they are today.</p>
<p>In that belief are the roots of recovery – and it’s happening in spite of the fact that demand for the underlying product isn’t going up. I think it’s healthy that participants are able to build a capital structure that works with the uncertainty.</p>
<p><b>Nastro:</b> The lack of organic growth is pushing management teams to look at strategic alternatives to provide upside for shareholders. Investors continue to reward transactions with a clear, coherent strategy, and a shift toward a more pure-play business model, with the ability to build scale and bring competitive advantages.</p>
<p>Several diversified utilities own merchant generation assets and their stocks are reflecting limited equity value for these businesses. There are advantages for power generation being held in a pure play, publicly traded merchant genco. If you think about how a merchant IPP is valued in the public markets, investors focus on EBITDA and cash flow, compared to earnings per share and capital structure for utilities. It’s a different valuation methodology, and IPP investors are comfortable with a company that’s non-investment grade. </p>
<p>Since the equity market trough in 2009, interest-rate sensitive stocks have outperformed in the context of a low rate environment. Investors have been searching for new yield-oriented products. NRG Yieldco, for example, demonstrated a compelling growth profile in addition to traditional yield. In some situations, renewables and contracted fossil assets can be more appropriately valued in a yieldco construct than they can in a traditional utility or IPP model. These structures can result in a lower cost of capital, which can facilitate growth opportunities. </p>
<p>Investors are looking for carve-out opportunities, and a yieldco is a new way to unlock value and raise new equity capital. Another example is OGE and CenterPoint putting together their midstream businesses and looking to take the joint venture public. </p>
<p><b>LeBlanc:</b> Companies are pursuing yieldcos because MLPs are too hard. It will take legislative action to get renewable resources to qualify for MLPs. That’s not going to happen, but people will spend a lot of time trying.</p>
<p>Asset owners are watching the NRG Yield and TransAlta Renewables yieldcos, and saying “me too.” There’s a backlog lining up to get to market. Some will be a good fit, and others will fall by the wayside. But there’s a limited window for these structures. As interest rates go up, yield vehicles will become less attractive.</p>
<p><b>FORTNIGHTLY</b> Utility capex spending has increased in the last couple of years, to a record high in 2012. Do you see these levels continuing? What’s the outlook for new projects, and what factors are at play?</p>
<p><b>Kind:</b> Bonus depreciation mitigated income tax payments for many utilities, and that helped support some capital programs. Looking at EEI data, I see utilities continuing to spend in excess of 2-times depreciation on new capital programs. At that level, utilities will have to raise capital as bonus depreciation ends. And that’s without a lot of new power plants probably being added. If you add substantial power plant activity – which frankly I don’t see happening in the near term – you’d have to dramatically increase the level required. </p>
<p>At what point do companies in a no-growth or low-growth environment think about deferring capex to mitigate the need for rate increases? We saw that happen in the 2007 and ’08 timeframe, with deferrals on capital programs. I don’t think anyone is suggesting demand growth will return at a robust level, as a function of the fact nobody is projecting the economy will grow at a robust level. The economists discuss growth in the 2- to 3-percent range. Further, the Energy Information Administration talks about de-linkage of GDP growth and electricity usage. They’re predicting electricity usage will grow at less than 1 percent per year, and that’s without assuming any substantial change in the way customers behave in the future.</p>
<p><b>Napolitano:</b> I would disagree that we aren’t seeing investment in new power plants. I’ve been involved in activity that indicates lots of people are thinking about natural gas as their transition fuel, and they’re constructing a lot of peaking plants, with combined-cycle projects in process and coming. New projects were finalized in California as a result of an RFP process three years ago, and are coming online now. They’re needed to deal with intermittency of renewables coming onto the grid. In Texas, Panda Power Funds has announced multiple merchant plants and has put together a capital structure to support development financing. In PJM, state contracts for new projects are going through a variety of legal challenges, but the [725-MW] CPV Shore plant in New Jersey recently reached financial closing. Five or six new gas-fired plants cleared in PJM forward auctions on the assumption they’ll get financed and constructed. Many people want to build new gas-fired plants in PJM to deal with capacity requirements.</p>
<p>On the rate-base side, Consumers Energy in Michigan recently announced plans to build a new [700-MW, $750 million] combined-cycle plant. Others are looking at projects too. All incremental baseload power capacity will come from combined-cycle gas turbine plants, in my opinion, whether in competitive wholesale markets or in rate bases. The people who sell this equipment are quite busy with projects right now.</p>
<p><b>Ryan Wobbrock, Moody’s:</b> In general capex is peaking this year and going into 2014 as companies complete the environmental investments they need to comply with EPA’s MATS rules, and to meet renewable portfolio standards for 2015 and 2020. The industry will be turning to an execution strategy, with companies finalizing their large expenditures and trying to catch up with operating costs to make it through to the next rate case.</p>
<p><b>Haggerty, Moody’s: </b>One of the wild cards is environmental capex. There’s a scenario where EPA will impose more onerous regulations going forward. That’s a longer-term issue.</p>
<p><b>Nastro:</b> A large amount of the capex is behind us, and many companies will be focused on an execution strategy in 2014 and 2015. Over the last couple of years, low gas prices and low interest rates have subsidized customer bills and made it easier for regulatory commissions to grant cost recovery with minimal effect on rates. I don’t see any major problems financing capex going forward, especially given the sector’s ability to finance through the financial downturn. However, the lack of top-line growth is obviously a headwind for the sector, as companies contemplate capex investments in the future.</p>
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Thu, 03 Oct 2013 13:42:26 +0000meacott16819 at http://www.fortnightly.comPPAs for DGhttp://www.fortnightly.com/fortnightly/2013/06/ppas-dg
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>What every real property owner should know.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Nicholas A. Giannasca</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Nicholas A Giannasca</b> is a partner with the law firm of Blank Rome LLP and a co-chair of the firm’s energy and natural resources industry group. He acknowledges the assistance of Carlos E. Gutierrez and Elizabeth A. Stern, both associates at the firm.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - June 2013</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>For reasons ranging from good corporate citizenship to the desire to enhance the market value of their properties, owners of real property, particularly commercial property, are exploring ways to reduce energy costs and become more efficient consumers of energy. Among the options available to achieve these goals are building retrofits, the installation of energy efficiency measures, and in certain cases, the installation of onsite power, also known as distributed generation (DG) facilities,<b><sup><a href="http://www.fortnightly.com/fortnightly/2013/06/ppas-dg?page=0%2C9#1" title="In this analysis, the typical distributed generation facility has a name-plate installed capacity of 2 MW or less. While many of the contractual and regulatory considerations examined are equally applicable to units sized above 2 MW, other unique contractual and regulatory considerations (e.g., more complex interconnection procedures) could be triggered in connection with larger facilities.">1</a></sup></b> such as photovoltaic (PV) and combined heat and power (CHP) units. </p>
<p>One key impediment to the installation of DG often has been the lack of viable financing alternatives for property owners who have determined that an outright purchase (<i>i.e.,</i> self-financing) of the facility, and the associated operation and maintenance, isn’t an attractive business investment. While many owners might be interested in DG, they might not have the budget flexibility for a significant capital outlay or the expertise to operate sophisticated generation facilities. Additionally, many owners might not be aware of—or aren’t well positioned to benefit directly from—the myriad federal, state, and local incentives (<i>e.g.,</i> investment tax credits and accelerated depreciation) available to developers and owners of distributed generation.</p>
<p>The solar industry responded to the market signals for a non-ownership financing alternative with the proliferation of zero capital-outlay products featuring a power purchase agreement (PPA).<b><sup><a href="http://www.fortnightly.com/fortnightly/2013/06/ppas-dg?page=0%2C9#2" title="At times, these zero capital-outlay packages are structured as leases under which the host makes a series of lease payments to the owner of the distributed generation facility in return for acquiring title to the electricity produced by the facility. Issues involving power purchase agreements are, for the most part, equally relevant to such a lease structure.">2</a></sup></b> Under this structure, a developer of the generation facility assumes all financing, construction, ownership, operation, and maintenance risk, and enters into a PPA with the host property owner for the sale of electricity over a sufficiently long duration to accommodate financing, and to permit a return on the investment. Without expending any capital funds, the property owner or host benefits from lower-cost electricity—often discounted from the otherwise applicable utility rate—while shifting to the developer much of the ownership and operational risk related to the DG facility.<b><sup><a href="http://www.fortnightly.com/fortnightly/2013/06/ppas-dg?page=0%2C9#3" title="The PPA structure will typically permit the sale of energy products to be treated as a service and, hence, an off-balance sheet transaction. The factors that could affect the characterization of a PPA as a service contract for tax purposes are beyond the scope of this analysis. Please refer to the section titled “Purchase Options” for an examination of how purchase options can impact the tax characterization of a PPA.">3</a></sup></b> The resulting expansion of distributed solar generation, particularly in the residential arena, is largely attributable to the PPA model, and the CHP industry has taken note. Market participants increasingly are developing PPA-based products for the installation of CHP facilities.<b><sup><a href="http://www.fortnightly.com/fortnightly/2013/06/ppas-dg?page=0%2C9#4" title="Indeed, new financing products and arrangements are being considered by legislators and investors, including securitization, real estate investment trusts (REIT), master limited partnerships, and crowd funding, that have the potential to stimulate renewable energy development and the use of more standardized PPAs.">4</a></sup></b></p>
<p>Whether an owner considers solar or CHP distributed generation under a PPA model, there are certain legal risks and issues that need to be considered. While this analysis focuses on the risks and issues of importance to the host (<i>i.e.</i>, the buyer under the PPA), it also addresses issues and considerations pertinent to the viewpoint of the developer where appropriate. In some cases, negotiated compromises will facilitate the execution of the PPA.</p>
<h4><b>DG Design and Contracting</b></h4>
<p>The host should have a significant role in the siting and design of the facility, including the right to review and approve designs, and the right to inspect the facility during construction. Since the facility will be located on the host’s roof, or within the host’s premises in the case of a CHP facility, the host will have an important and legitimate desire to ensure that the premises will be able to accommodate the location and operation of the facility safely and reliably. The host should ensure, often with the assistance of an engineer consultant, that the facility is sited and designed not only to operate reliably but also to operate in a manner that minimizes any effect on the remainder of the host’s premises. As important, the host will need to draft contractual language in the PPA excusing the host from any liability associated with its review of the design and specifications of the facility.</p>
<p>The host will need to provide appropriate property access rights to the roof or to other designed areas of the host’s premises where the DG facility is to be located. The PPA will typically provide for the developer to have such access during construction and during the operation of the facility throughout the term of the PPA, including—if applicable—the period during which the facility will be removed from the host’s premises. The manner of conveying such rights to the developer is through access language in the PPA or through the execution of a separate site lease. In either case, PPAs typically don’t provide for the host to receive, or for the seller to pay, compensation for such access. </p>
<p>The primary obligation of the host under a PPA structure is the requirement to purchase electricity—and thermal energy under a CHP PPA. The host should insist on drafting clear terms regarding its purchase obligation, including the amount of electricity and thermal energy to be purchased. Will the developer require the host to purchase all of the production of the facility, or just the amount that the host needs at the time of production and delivery? If the former, then the host must be concerned with the economic consequences of purchasing more than its full requirements. For example, if the host is eligible for a utility net metering program (which permits the host to inject the excess electricity into the utility grid and receive a billing credit from the utility) then the economic consequences of buying more than the host requires can be mitigated.<b><sup><a href="http://www.fortnightly.com/fortnightly/2013/06/ppas-dg?page=0%2C9#5" title="As discussed in the section titled “Regulatory Considerations,” the host’s eligibility to engage in net metering is an important consideration for both the host, and the developer or seller. If the host can’t engage in net metering (e.g., because the distributed generation facility is too large), then the host won’t want to assume a purchase obligation that extends beyond its consumption needs at the time the electricity and thermal energy is delivered. Likewise, the developer or seller will need to consider options for disposing of excess electricity if net metering is unavailable to the host (e.g., wholesale sales of electricity into available energy markets), several of which will trigger regulatory compliance issues, such as the need for Federal Energy Regulatory Commission approval to engage in wholesale sales of electricity. The disposal of excess thermal energy, while not as complex as the disposal of excess electricity, might also entail regulatory compliance issues.">5</a></sup></b></p>
<p>The pricing methodology of many PPAs is based on a fixed, volumetric rate (<i>e.g.,</i> $/MWh) applied to the amount of electricity delivered at a designed point of delivery (<i>e.g.,</i> a newly installed meter located at or near the facility). In order to provide economic benefits to the host, the rate is often set at a current-discount from the otherwise applicable utility rate, and is often subject to a fixed price escalator. Typical annual escalation rates in today’s market are between 2 percent and 4 percent. The risk associated with this common structure for the host is that the overall cost of power under the PPA can be higher than the host’s costs would have been if it had purchased its power from the utility. Over the course of a typical PPA term of 15 to 20 years, there’s a possibility that the fixed rate can exceed the utility rate. One method for addressing this risk is to subject the fixed rate to periodic adjustment to reflect a discount from the then-current utility alternative rates, while always being subject to the minimum payment obligation.<b><sup><a href="http://www.fortnightly.com/fortnightly/2013/06/ppas-dg?page=0%2C9#6" title="A PPA pricing model that has been used in some cases is the fixed-discount structure, in which the PPA price is always set at a fixed discount (e.g., 10 percent) from the otherwise applicable utility rate. The advantage of this structure is that the buyer knows it will always pay a discount from the utility rate, but the disadvantage is that the rate will fluctuate with changes in the utility benchmark rate, thereby hampering price certainty.">6</a></sup></b></p>
<p>In order to finance the construction of the facility, the developer will need to show that the PPA is bankable, which means that the PPA will support the financeability of the project. One key component in rendering a PPA bankable is the presence of a minimum payment obligation on the part of the host that isn’t dependent on how much the host actually consumes. The minimum payment obligation is set at a level to ensure that the developer can at least cover its financing costs (loan principal and interest, insurance, etc.) over the term of its loan plus additional fees. The host that opposes such a provision could risk jeopardizing the project, but there are ways to protect the host and to facilitate financing under these circumstances. For example, the difference between any fixed minimum and the amount actually owed by the host can be tracked in a notional account and can be returned after the financing period—which typically is shorter than the PPA term—expires through an additional discount to the purchase rate.</p>
<h4>Terms and Guarantees</h4>
<p>The developer typically will require a duration of between 10 and 20 years, subject to certain tax considerations, for the PPA. The term is often crafted to commence on the commercial operation date (COD) of the facility, which is specifically defined in the PPA. Typically, the COD is deemed to have occurred when the facility construction is complete, the facility is properly connected to the utility grid and tested, and the facility is operated for a minimum period of time to demonstrate that it can operate within specified technical parameters, the confirmation of which can be reflected in a report by an independent engineer. This engineer likely will provide a report to the project lender confirming the COD and the satisfaction of required technical criteria. The commercial operation of the facility must be coordinated among a number of parties, including the host, the developer and the utility to whose distribution system the facility will be interconnected.</p>
<p>In order to motivate the developer to keep the development of the facility on track, the PPA will often contains milestone dates by which certain key project developments need to be accomplished, such as closing financing, ordering equipment, and directing the commencement of construction under a major construction agreement with a contractor. A host would do well to require such milestone performances but also to couple each such provision with a liquidated damages clause to compensate the host for the economic harm that it might suffer as a result of the delay in meeting the milestone. If the electricity—and thermal energy—is being purchased at a discount from the otherwise applicable utility tariff, for example, then any milestone delay simply defers the commencement of dollar savings to the host’s detriment.</p>
<p>PPAs typically contain output guarantees, or what are sometimes referred to as “minimum performance guarantees.” These provisions assure the host that the DG will actually perform (<i>i.e.,</i> will generate a specified minimum amount of electric and thermal energy, or both) as promised. The host owner should bargain aggressively for such a guarantee, even if the host, the buyer under the PPA, is only obligated to purchase its energy requirements. The installation of a distributed generator on the host property entails risk for the host (<i>e.g.,</i> misoperation affecting the remainder of the host premises). To induce the host to accept this risk, the developer must provide assurances that the distributed generator will perform consistent with its promised capability. Both the developer and the host have a common and legitimate interest in maximizing the performance—and the persistence of that performance—of the distributed generator over the course of the PPA.</p>
<p>A provision often confused with a performance guarantee is an availability guarantee. The key difference between the two is that a performance guarantee will provide assurance of how much output (electrical and thermal) the facility will produce assuming that it’s operating within certain parameters. An availability guarantee provides assurance as to how often (<i>i.e.,</i> what percentage of all available hours of operation) the facility will operate. Another way to consider these two different guarantees is through a consideration of risk. If a host owner receives a performance guarantee with no availability guarantee, then the host assumes the risk that the facility doesn’t operate. </p>
<p>From a practical perspective, if the generation facility performs at lower availability levels, the host will suffer a loss of economic benefits. To protect against that loss, the host should negotiate for both a performance guarantee and an availability guarantee with an express obligation by the developer to make a designated payment to the host if either or both aren’t met. Such a payment would be sufficient to place the host in the same position economically as if the facility had produced the higher, expected level of output. For example, an amount payable to the host equal to the product of: i) the amount of energy not produced and delivered; and ii) the difference between the PPA rate and the presumably higher alternative utility rate should be economically protective of the host.</p>
<h4>Performance and Default</h4>
<p>There are myriad obligations of a seller under a long-term PPA and, consequently, ample opportunity for a seller default to be triggered. Some potential seller defaults include: a failure to commence commercial operation by the requested milestone date; a failure to deliver the agreed upon output of the facility; the facility’s failure to attain a certain availability factor; and the seller’s failure to properly maintain the facility.</p>
<p>Given the numerous possibilities for a seller default under a PPA, and the long duration of such contacts, it’s critical that the host have clearly designed remedies that can be exercised in the event of a default, including the host’s right to terminate the PPA. In addition to the right to terminate, the host should have the right to demand that the seller or developer pay damages as compensation. Typically, the measure of damages is based on the amount of money that, if paid, would place the host in the position it would have been in had the contract been performed by the seller. This measure of compensatory, direct damages would either be specified in the PPA for each year of the term (<i>i.e.,</i> liquidated damages) or it would be calculated as the product of the amount of energy (electrical and thermal) not delivered by the seller and the positive differential between the market cost to replace that energy and the cost that the host would have paid under the contract had the promised energy been delivered (<i>i.e.,</i> cover damages).</p>
<p>If the contract is terminated due to the seller’s default, then the host must have the right to require the seller to remove the generation facility from the premises and restore the premises to the same condition, except for reasonable wear and tear, that it was in on the effective date of the PPA.</p>
<p>In addition to being mindful of seller’s non-performance, and available remedies, the host must be careful in structuring remedies available to the developer if the host breaches the PPA. In addition to the right to terminate the PPA, the developer will often negotiate for a formula or scheduled form of liquidated damages that seek to place the seller in the same economic position it would have been in had the PPA been fully performed. The host should ensure that the formula or schedule bears a reasonable relationship to the seller’s losses (<i>i.e.,</i> it isn’t punitive). As well, the host should require the seller to transfer title to the facility to the host once the damages are paid by the host.</p>
<p>If the host ceases to do business at the location specified in the PPA, there are several options for the host: a) the host can pay to move the facility and continue to buy electricity at the new location; b) the host can attempt to negotiate an assumption of the PPA (perhaps with a release of the host from further liability) with the new occupant of the premises; or c) the host can pay a liquidated termination fee, either based on a formula or schedule, and be released from the contract—with a transfer to the buyer of title to the facility.</p>
<p>Given the diverse monetary obligations present in a typical PPA, it’s often the case that a party might require the other party to post assurance or security that it can perform. For example, a seller could require a buyer who isn’t deemed sufficiently creditworthy to post security (<i>e.g.,</i> letter of credit or parent guarantee) to support the buyer’s obligation to pay for energy. Likewise, a buyer might require a seller—who is often a special purpose entity (SPE)—to post security to supplement the SPE’s primary asset, namely, the DG facility.</p>
<p>In addition to assurances or security that might be required to be in place at the inception of the PPA term, it’s customary for a PPA to contain a reciprocal demand-for-assurances provision that permits a party with a reasonable basis for being insecure about the party’s ability to perform to demand assurances (<i>e.g.,</i> the posting of collateral). If the assurance demanded isn’t posted, or isn’t posted in a timely way, the demanding party typically can declare a breach of contract.</p>
<p>Parties to a PPA, particularly buyers—who are more often than not the party required to post security—should be careful to draft assurance and security provisions that can be easily implemented with precise triggering events, that reflect express criteria for the amount and type of security to be posted, and that provide ample opportunity to post, or to cure an inadvertent failure to post, a demanded assurance.</p>
<h4>Purchase Options</h4>
<p>Many PPAs provide an election for the host to purchase the facility at the expiration of the PPA term. Some PPAs also provide for the host to purchase the facility at specified points during the PPA. Hosts and developers or sellers should be aware of the tax and financing considerations related to these purchase options. </p>
<p>With respect to purchase options at the end of the PPA term, the parties need to craft the option to ensure that a) the duration of the PPA term—including the initial term and extensions and renewals—is no greater than 80 percent of the useful life of the DG facility (<i>e.g.,</i> a distributed generator with a useful life of 25 years could be the basis of a PPA with a term, including extensions and renewals, not exceeding 20 years), and b) the purchase option, if exercised, will be at the facility’s fair market value, determined at the time the option is exercised. A PPA structure that doesn’t satisfy these criteria might be considered to have conferred tax ownership of the facility on the host, thereby conferring the tax benefits of ownership on the host instead of the developer or seller. Such a result could be very problematic from a financing and tax perspective for both the seller and the host.</p>
<p>Purchase options that can be triggered by the host before the expiration of the PPA are subject to other considerations. One of the most compelling considerations for the developer is avoiding recapture of investment credits and depreciation deductions, which are vital to the initial financing of the project. The investment credit for solar equipment is 30 percent of the cost of the equipment (and 10 percent for CHP), and represents an important component in the developer’s ability to finance construction and attract investors. The taxpayer who claims the credit, however, might be required to repay some or all of the credit (<i>i.e., </i>the incentive can be clawed back) if the property is sold or transferred during the first five years after it achieves commercial operation. Accordingly, most PPAs won’t contain a purchase option excusable during the first five years following commercial operation. The host and the developer or seller are well-advised to consult with counsel regarding the tax and commercial implications of purchase options they might be contemplating in a PPA.</p>
<h4>Regulatory Considerations</h4>
<p>There are a number of regulatory considerations for the host to consider, including certain considerations directly affecting the developer or seller. It’s extremely important for both the host and the developer or seller, for example, to consult the applicable regulations of the local utility serving the host premises. In the case of a solar installation, these regulations might be limited to the local electric utility. For a CHP facility, however, the applicable regulations can include those of the utility supplying the premises with electricity, gas and steam. These utility regulations can affect the timing of the installation, the cost—which will largely be borne by the seller or developer in a PPA structure—and the economic effect of the arrangement from both the developer and seller and the host’s perspective. </p>
<p>Utility regulations might address the technical requirements for interconnecting the distributed generator, whether those regulations address electric interconnection requirements or natural gas piping infrastructure. These technical requirements might affect the cost to construct the distributed generator and, hence, the price the seller or developer might offer. Additionally, the complexity of the regulations and the duration of the process undertaken pursuant to the utility’s procedures can have a profound effect on the timing for constructing the facility and placing it into commercial operation. For example, the number and scope of interconnection studies that the electric utility needs to conduct to determine the effect of the distribution generator on the safety and reliability of the utility’s distribution system could extend the commercial operation date.</p>
<p>An important consideration for the developer or seller involves the level of regulation that might be imposed on the developer or seller by federal and state authorities if the seller engages in both retail and wholesale sales of excess energy.<b><sup><a href="http://www.fortnightly.com/fortnightly/2013/06/ppas-dg?page=0%2C10#7" title="If the developer or seller structures the PPA such that it has the right to sell all of the output of the generation facility to the host, then the regulatory considerations for the seller are reduced, but there are heightened regulatory considerations for the host. If the host doesn’t have a mechanism to dispose of energy that it doesn’t need for some economic return, but is forced to buy the excess, then the economic consequences for the host could be detrimental.">7</a></sup></b> The host needs to be concerned about this level of regulation because the easier it is for the developer or seller to engage in these sales of excess energy, the greater the likelihood that the seller will realize additional revenue. That additional revenue not only bolsters the seller or developer’s financial wherewithal to perform under the PPA (<i>e.g.,</i> undertake operations and maintenance tasks), but also provides a potential source of additional revenue for the host. It’s often the case that a seller or developer might offer, or a host might negotiate for, a percentage of the revenue from such excess sales.<b><sup><a href="http://www.fortnightly.com/fortnightly/2013/06/ppas-dg?page=0%2C10#8" title="A host and developer or seller might wish to consider whether additional generation capacity can be installed on the premises—without triggering onerous regulatory or financial burden—for the purpose of providing incremental electricity for sale (e.g., to an energy service company or directly into the available energy and capacity markets).">8</a></sup></b></p>
<p>There are two key regulatory considerations for the host. First, the host must consider whether it’s eligible for net metering. Under net metering programs, energy from the project will offset the host’s retail purchase from its local utility, and when the project is producing more power than the host needs, the utility meter runs backwards, reducing the net amount of the host’s electric purchases. Most states require that utilities implement some form of a net metering program. There are often size, technology, and other restrictions, however, that limit eligibility for the program,<b><sup><a href="http://www.fortnightly.com/fortnightly/2013/06/ppas-dg?page=0%2C10#9" title="The net metering programs offered by utilities in New York, for example, are constrained by size limitations created by statute (i.e., section 66-l of the Public Service Law), which creates the following size limitations on eligibility: a) solar electric (residential): not more than 25 kW; b) solar electric (non-residential): not more than 2,000 kW; c) farm waste: not more than 1,000 kW; d) micro-combined heat and power: not more than 10 kW; e) fuel cell (residential): not more than 10 kW; f) fuel cell (non-residential): not more than 1,500 kW; g) micro-hydroelectric (residential): not more than 25 kW; and h) micro-hydroelectric (non-residential): not more than 2,000 kW. New York’s net metering law also authorizes certain “customer generators” to engage in “virtual” net metering by permitting net metering credits to apply to meters serving property owned or leased by that customer generator that is located in the same service territory and load zone. See Section 66-l(e).">9</a></sup></b> so as with retail sales in general, the host should become informed of the local rules prior to negotiation of a PPA.</p>
<p>Second, the host should consider the economic effect of the local utility—whether it’s the electric, gas, or steam utility—placing the host on a different tariff for those purchases to be made by the host for supplemental energy (<i>i.e.,</i> energy not supplied by the on-site or distributed generation facility). Very often utilities will place a customer with on-site generation on what is referred to as a “standby service” tariff. Such tariffs commonly have a rate structure consisting of a fixed monthly contract demand charge and a volumetric charge that is applied to the amount of energy consumed. Because the contract demand charge can be established on the assumption that the utility needs to be compensated for standing ready to serve the entire host load (<i>i.e.,</i> it assumes that the DG facility isn’t operating), this charge could be onerous. Therefore, a host should factor potentially higher standby service charges into the calculation of net economic benefits associated with the installation of a DG facility. </p>
<p>Depending on the state in which the DG facility is located, and the technology adopted to produce electricity, the generation of electricity from that unit can also create a separate commodity referred to as a renewable energy certificate (REC), or environmental attribute.<b><sup><a href="http://www.fortnightly.com/fortnightly/2013/06/ppas-dg?page=0%2C10#10" title="This analysis refers to the broad group of such certificates and attributes as RECs. A developer or seller and host should consult with applicable state law to determine what type of commodity the proposed generation facility may produce. If the host has an important interest to be served by showing that it has purchased the RECs associated with the facility, then the host must make sure that the PPA contains express language transferring title to the RECs to the buyer and requiring the seller to take reasonable steps (e.g., submitting a certificate confirming that the facility produces renewable energy) to cooperate with the buyer to ensure that the buyer receives the economic benefits of the acquired RECs.">10</a></sup></b> In certain states, this separate REC commodity can have value for the title holder because the REC might be marketable (<i>i.e.,</i> it can be sold in a liquid market to realize revenue). Often, utilities might be willing buyers because they’re required under a related law (<i>i.e.,</i> a renewable portfolio standard (RPS)) to procure a certain percentage of the power they purchase from renewable resources. Often such a legal requirement permits the utility or other entity obligated to meet the RPS requirement the option to buy renewable power or RECs.</p>
<p>Because RECs might have economic value separate from the energy produced by the generation facility, the developer or seller will negotiate for a provision in the PPA that allocates all right and title to those RECs to the developer or seller. While a host might attempt to negotiate for a revenue-sharing provision, the host should be prepared for a resistant developer or seller, who will argue that the main economic benefit for the host is the discount from utility rates and not additional revenue. As well, the developer or seller will assert that it’s assuming the financing construction and operation risk related to the facility and, hence, it’s fair to capture such incremental economic value for its account.</p>
<p>A provision that engenders much negotiation in a PPA is the change in law and regulatory-out clause (the “reg-out clause”). As typically structured, a reg-out clause will permit the seller, but usually not the buyer, to either modify the sales price or terminate the agreement if a change in law or regulation imposes a requirement on seller that materially affects the seller’s ability to perform. An example could be a new regulation that imposes an incremental cost on the seller (<i>e.g.,</i> an RTO or ISO imposes a new fee on energy scheduled by the seller into the market administered by the RTO or ISO). The seller will want to flow the increases cost through to the host and the host, not surprisingly, will resist the increase in cost.</p>
<p>The parties often can strike a compromise based on one of several alternatives. A common resolution permits the seller to allocate incremental costs to the buyer associated with a change in law or regulation, if the increase in cost is within a negotiated percentage cap. If the proposed increase exceeds the percentage cap, then the seller and buyer are required to negotiate for modification to the PPA to restore the economic balance of the agreement. If the parties fail to arrive at an amendment to the PPA to restore such economic benefit, then the buyer can be given the right to terminate and the parties will negotiate whether the right to terminate entails an obligation to pay the seller some form of termination payment. Another alternative involves a narrowly tailored reg-out clause that specifically identifies the anticipated event or development that will trigger a rate modification. Combining such a limited clause with the negotiated cap format gives the host a level of protection against rate adjustments that could be materially detrimental.</p>
<h4>Coordinating Agreements</h4>
<p>For a host considering the installation of a DG facility, several ancillary arrangements need to be examined to ensure that the installation and PPA don’t detrimentally impact the host.</p>
<p>For example, if the host owns premises that are subject to a mortgage or security interest, then the host should consider whether the installation of the DG facility and its operation will trigger any defaults under the documentation creating the mortgage or security interest. A related issue for the host is its ability to obtain, if requested by the developer or seller, a waiver from the holder of the mortgage on the host’s premises. Often developers or sellers will want such a waiver (as will the lenders of the developer or seller) to protect the generation facility (which will be deemed personal property and not a fixture) from foreclosure by the mortgage holder. The process for obtaining such a waiver might be protracted and needs to be carefully managed by the host since it could affect the timing for financing, and hence constructing, the generation facility. </p>
<p>A host’s insurance requirements also need to be examined if distributed generation is being seriously contemplated. The presence of the facility likely will change the risk profile of the host, which could increase the cost of existing coverage or require that the host procure new coverage. The additional cost of insurance coverage typically won’t be absorbed by the developer or seller and, hence, it will have a direct effect on the anticipated economics of the transaction for the host. </p>
<p>The PPA structure for financing the installation of distributed generation has stimulated a significant amount of solar PV construction and development, and can successfully provide the impetus for the growth of CHP installations. But, the PPA structure isn’t without risks and exposure for both the developer and the host. In exchange for allocating the risk of construction operation and maintenance to the developer, the host under a PPA remains subject to liability (<i>e.g.,</i> damages for failing to accept power) that, while potentially detrimental, can be well managed with properly drawn PPAs. A well-drafted PPA can adequately protect the legitimate interests of both parties while achieving the level of bankability that is crucial for financing.</p>
<p> </p>
<h4>Endnotes:</h4>
<p><a name="1" id="1"></a>1. In this analysis, the typical distributed generation facility has a name-plate installed capacity of 2 MW or less. While many of the contractual and regulatory considerations examined are equally applicable to units sized above 2 MW, other unique contractual and regulatory considerations (<i>e.g.,</i> more complex interconnection procedures) could be triggered in connection with larger facilities.</p>
<p><a name="2" id="2"></a>2. At times, these zero capital-outlay packages are structured as leases under which the host makes a series of lease payments to the owner of the distributed generation facility in return for acquiring title to the electricity produced by the facility. Issues involving power purchase agreements are, for the most part, equally relevant to such a lease structure.</p>
<p><a name="3" id="3"></a>3. The PPA structure will typically permit the sale of energy products to be treated as a service and, hence, an off-balance sheet transaction. The factors that could affect the characterization of a PPA as a service contract for tax purposes are beyond the scope of this analysis. Please refer to the section titled “Purchase Options” for an examination of how purchase options can impact the tax characterization of a PPA.</p>
<p><a name="4" id="4"></a>4. Indeed, new financing products and arrangements are being considered by legislators and investors, including securitization, real estate investment trusts (REIT), master limited partnerships, and crowd funding, that have the potential to stimulate renewable energy development and the use of more standardized PPAs. </p>
<p><a name="5" id="5"></a>5. As discussed in the section titled “Regulatory Considerations,” the host’s eligibility to engage in net metering is an important consideration for both the host, and the developer or seller. If the host can’t engage in net metering (<i>e.g.,</i> because the distributed generation facility is too large), then the host won’t want to assume a purchase obligation that extends beyond its consumption needs at the time the electricity and thermal energy is delivered. Likewise, the developer or seller will need to consider options for disposing of excess electricity if net metering is unavailable to the host (<i>e.g.,</i> wholesale sales of electricity into available energy markets), several of which will trigger regulatory compliance issues, such as the need for Federal Energy Regulatory Commission approval to engage in wholesale sales of electricity. The disposal of excess thermal energy, while not as complex as the disposal of excess electricity, might also entail regulatory compliance issues.</p>
<p><a name="6" id="6"></a>6. A PPA pricing model that has been used in some cases is the fixed-discount structure, in which the PPA price is always set at a fixed discount (<i>e.g.,</i> 10 percent) from the otherwise applicable utility rate. The advantage of this structure is that the buyer knows it will always pay a discount from the utility rate, but the disadvantage is that the rate will fluctuate with changes in the utility benchmark rate, thereby hampering price certainty.</p>
<p><a name="7" id="7"></a>7. If the developer or seller structures the PPA such that it has the right to sell all of the output of the generation facility to the host, then the regulatory considerations for the seller are reduced, but there are heightened regulatory considerations for the host. If the host doesn’t have a mechanism to dispose of energy that it doesn’t need for some economic return, but is forced to buy the excess, then the economic consequences for the host could be detrimental.</p>
<p><a name="8" id="8"></a>8. A host and developer or seller might wish to consider whether additional generation capacity can be installed on the premises—without triggering onerous regulatory or financial burden—for the purpose of providing incremental electricity for sale (<i>e.g.,</i> to an energy service company or directly into the available energy and capacity markets).</p>
<p><a name="9" id="9"></a>9. The net metering programs offered by utilities in New York, for example, are constrained by size limitations created by statute (i.e., section 66-l of the Public Service Law), which creates the following size limitations on eligibility: a) solar electric (residential): not more than 25 kW; b) solar electric (non-residential): not more than 2,000 kW; c) farm waste: not more than 1,000 kW; d) micro-combined heat and power: not more than 10 kW; e) fuel cell (residential): not more than 10 kW; f) fuel cell (non-residential): not more than 1,500 kW; g) micro-hydroelectric (residential): not more than 25 kW; and h) micro-hydroelectric (non-residential): not more than 2,000 kW. New York’s net metering law also authorizes certain “customer generators” to engage in “virtual” net metering by permitting net metering credits to apply to meters serving property owned or leased by that customer generator that is located in the same service territory and load zone. <i>See</i> Section 66-l(e).</p>
<p><a name="10" id="10"></a>10. This analysis refers to the broad group of such certificates and attributes as RECs. A developer or seller and host should consult with applicable state law to determine what type of commodity the proposed generation facility may produce. If the host has an important interest to be served by showing that it has purchased the RECs associated with the facility, then the host must make sure that the PPA contains express language transferring title to the RECs to the buyer and requiring the seller to take reasonable steps (<i>e.g.,</i> submitting a certificate confirming that the facility produces renewable energy) to cooperate with the buyer to ensure that the buyer receives the economic benefits of the acquired RECs.</p>
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<div class="field-label">Tags:&nbsp;</div>
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<a href="/tags/retrofit">Retrofit</a><span class="pur_comma">, </span><a href="/tags/efficiency">efficiency</a><span class="pur_comma">, </span><a href="/tags/distributed-generation">Distributed generation</a><span class="pur_comma">, </span><a href="/tags/dg">DG</a><span class="pur_comma">, </span><a href="/tags/photovoltaic">Photovoltaic</a><span class="pur_comma">, </span><a href="/tags/pv">PV</a><span class="pur_comma">, </span><a href="/tags/combined-heat-and-power">combined heat and power</a><span class="pur_comma">, </span><a href="/tags/chp">CHP</a><span class="pur_comma">, </span><a href="/tags/incentive">incentive</a><span class="pur_comma">, </span><a href="/tags/tax-credits">Tax credits</a><span class="pur_comma">, </span><a href="/tags/depreciation">depreciation</a><span class="pur_comma">, </span><a href="/tags/power-purchase-agreement">Power purchase agreement</a><span class="pur_comma">, </span><a href="/tags/ppa">PPA</a><span class="pur_comma">, </span><a href="/tags/risk">risk</a><span class="pur_comma">, </span><a href="/tags/blank-rome">Blank Rome</a><span class="pur_comma">, </span><a href="/tags/carlos-e-gutierrez">Carlos E. Gutierrez</a><span class="pur_comma">, </span><a href="/tags/elizabeth-stern">Elizabeth A. Stern</a><span class="pur_comma">, </span><a href="/tags/siting">Siting</a><span class="pur_comma">, </span><a href="/tags/design">design</a><span class="pur_comma">, </span><a href="/tags/liability">liability</a><span class="pur_comma">, </span><a href="/tags/access-rights">access rights</a><span class="pur_comma">, </span><a href="/tags/purchase-obligation">purchase obligation</a><span class="pur_comma">, </span><a href="/tags/net-metering">Net metering</a><span class="pur_comma">, </span><a href="/tags/volumetric-rate">volumetric rate</a><span class="pur_comma">, </span><a href="/tags/payment-obligation">payment obligation</a><span class="pur_comma">, </span><a href="/tags/commercial-operation-date">commercial operation date</a><span class="pur_comma">, </span><a href="/tags/cod">COD</a><span class="pur_comma">, </span><a href="/tags/milestone">milestone</a><span class="pur_comma">, </span><a href="/tags/minimum-performance-guarantee">minimum performance guarantee</a><span class="pur_comma">, </span><a href="/tags/availability-guarantee">availability guarantee</a><span class="pur_comma">, </span><a href="/tags/seller-default">seller default</a><span class="pur_comma">, </span><a href="/tags/right-terminate">right to terminate</a><span class="pur_comma">, </span><a href="/tags/special-purpose-entity">special purpose entity</a><span class="pur_comma">, </span><a href="/tags/spe">SPE</a><span class="pur_comma">, </span><a href="/tags/collateral">collateral</a><span class="pur_comma">, </span><a href="/tags/purchase-option">purchase option</a><span class="pur_comma">, </span><a href="/tags/regulatory-considerations">regulatory considerations</a><span class="pur_comma">, </span><a href="/tags/interconnection">Interconnection</a><span class="pur_comma">, </span><a href="/tags/piping-infrastructure">piping infrastructure</a><span class="pur_comma">, </span><a href="/tags/demand-charge">demand charge</a><span class="pur_comma">, </span><a href="/tags/volumetric-charge">volumetric charge</a><span class="pur_comma">, </span><a href="/tags/renewable-energy-certificate">renewable energy certificate</a><span class="pur_comma">, </span><a href="/tags/rec">REC</a><span class="pur_comma">, </span><a href="/tags/renewable-portfolio-standard">Renewable portfolio standard</a><span class="pur_comma">, </span><a href="/tags/rps">RPS</a><span class="pur_comma">, </span><a href="/tags/revenue-sharing">revenue-sharing</a><span class="pur_comma">, </span><a href="/tags/regulatory-out">regulatory-out</a><span class="pur_comma">, </span><a href="/tags/reg-out">reg-out</a><span class="pur_comma">, </span><a href="/tags/mortgage">mortgage</a><span class="pur_comma">, </span><a href="/tags/solar-pv">solar PV</a> </div>
</div>
Wed, 29 May 2013 21:07:48 +0000meacott16588 at http://www.fortnightly.com